Cement Head Remote Control and Tracking

ABSTRACT

The present disclosure is related to wellbore servicing tools used in the oil and gas industry and, more particularly, to remote control tracking of cement head operations. A system of the present disclosure includes a control device, an onboard device operably connected to a mechanical device of a cement head, and a tracking device, wherein the control device is configured to transmit a user command indicator via (i) a first command signal to the onboard device and (ii) a second command signal to the tracking device, wherein the onboard device is configured to operate the mechanical device in response to the first command signal and transmit a status indicator of the cement head to the tracking device via a report signal, and wherein the tracking device is configured to record the user command indicator and the status indicator.

BACKGROUND

The present disclosure is related to wellbore servicing tools used inthe oil and gas industry and, more particularly, to remote control andtracking of cement head operations.

During completion of oil and gas wells, cement is often used to solidifya well casing within the newly drilled wellbore. To accomplish this,cement slurry is first pumped through the inner bore of the well casingand either out its distal end or through one or more ports defined inthe well casing at predetermined locations. Cement slurry exits the wellcasing into the annulus formed between the well casing and the wellboreand is pumped back up toward the surface within the annulus. Once thecement hardens, it forms a seal between the well casing and the wellboreto protect oil producing zones and non-oil producing zones fromcontamination. In addition, the cement bonds the casing to thesurrounding rock formation, thereby providing support and strength tothe casing and also preventing blowouts and protecting the casing fromcorrosion.

Prior to cementing, the wellbore and the well casing are typicallyfilled with drilling fluid or mud. A cementing plug is then pumped aheadof the cement slurry in order to prevent mixing of the drilling mudalready disposed within the wellbore with the cement slurry. When thecementing plug reaches a collar or shoulder stop arranged within thecasing at a predetermined location, the hydraulic pressure of the cementslurry ruptures the plug and enables the cement slurry to pass throughthe plug and then through either the distal end of the casing or theside ports and into the annulus. Subsequently, another cementing plug ispumped down the casing to prevent mixing of the cement slurry withadditional drilling mud that will be pumped into the casing followingthe cement slurry. When the top cementing plug lands on the collar orstop shoulder, the pumping of the cement slurry ceases.

To perform the aforementioned cementing operations, a cement head orcementing head is usually employed. The cement head is arranged at thesurface of the wellbore and the cementing plugs are held within thecement head until the cementing operation requires their deployment.Various valves associated with the cement head are required to bemanipulated in order to perform the required tasks of the cement head.Such valves are typically manipulated manually, thereby requiring rigpersonnel to be in close proximity to the cement head and other wellboreequipment. In some cases, rig hands are required to be strapped andsuspended in the air in order to operate the valves. As can beappreciated, this presents a potential safety hazard.

BRIEF DESCRIPTION OF THE DRAWINGS

The following figures are included to illustrate certain aspects of thepresent disclosure, and should not be viewed as exclusive embodiments.The subject matter disclosed is capable of considerable modifications,alterations, combinations, and equivalents in form and function, withoutdeparting from the scope of this disclosure.

FIG. 1A is an isometric view of a cement head that embodies principlesof the present disclosure, according to one or more embodiments.

FIG. 1B is a cross-sectional view of a cement head that embodiesprinciples of the present disclosure, according to one or moreembodiments.

FIG. 1C is a cross-sectional view of a cement head that embodiesprinciples of the present disclosure, according to one or moreembodiments.

FIG. 1D is an isometric view of a cement head that embodies principlesof the present disclosure, according to one or more embodiments.

FIG. 2 is a front view of a cement head that embodies principles of thepresent disclosure, according to one or more embodiments.

FIG. 3 is a side view of a cement head that embodies principles of thepresent disclosure, according to one or more embodiments.

FIG. 4 is an isometric view of a cement head that embodies principles ofthe present disclosure, according to one or more embodiments.

FIG. 5 is a schematic view of a communication system that embodiesprinciples of the present disclosure, according to one or moreembodiments.

FIG. 6 is a block diagram of a communication system that embodiesprinciples of the present disclosure, according to one or moreembodiments.

FIG. 7 is a block diagram of a communication system that embodiesprinciples of the present disclosure, according to one or moreembodiments.

FIG. 8 is a flow chart showing steps performed by components of acommunication system that embodies principles of the present disclosure,according to one or more embodiments.

DETAILED DESCRIPTION

The present disclosure is related to wellbore servicing tools used inthe oil and gas industry and, more particularly, to remote control andtracking of components of a cement head.

The present disclosure provides an ability to operate valves of a cementhead remotely. By reducing or eliminating the need for personnel to bephysically present during operation of a cement head or other wellboreequipment, the exposure of such personnel to injury or harm that mayoccur during operation is reduced or eliminated. The present disclosurealso describes an ability to sense parameters of a cement head or otherwellbore equipment during operation. These parameters can be remotelyrecorded for further analysis. Signals may be received from both (1) acontrol device operated remotely by a user and (2) an onboard deviceresponsive to operation of the control device. These signals can bereceived by a tracking device remotely separated from both the remotecontrol device and the onboard control device. As a result, variousaspects of job performance with respect to multiple devices may berecorded. Performance, measured parameters, and status reported atvarious stages of an operation allow a well operator to review andanalyze such data after completion of a job. Such analysis may proveadvantageous in yielding valuable information to well operatorsregarding performance characteristics and needed optimizations.Moreover, the present disclosure describes embodiments to operate valvesof a cement head from a variety of remote locations without requiringrelocation of an associated tracking device. A mobile and portablecontrol device may be operated from a variety of locations within acommunication range of the cement head and the tracking device.

Referring to FIG. 1A, illustrated is a cement head 100 that may embodyone or more principles of the present disclosure, according to one ormore embodiments. While the cement head 100 is shown as having aparticular configuration and design, those skilled in the art willreadily recognize that other types and designs of cement heads mayequally be used and otherwise employ the principles of the presentdisclosure. The cement head 100 is generally a multi-function deviceused inline with a work string associated with a wellbore in ahydrocarbon fluid production well. Most generally, the cement head 100is used to deliver cement or other wellbore servicing fluids and/ormixtures to a wellbore through the work string to which the cement head100 is attached. The cement head 100 is also capable of delivering dartsand/or balls for activating or initiating some function of a tool orstructure associated with the work string.

In one embodiment of the present disclosure, the cement head 100includes an output module 102, two intermediate modules 104, and aninput module 106. Each of the output module 102, intermediate modules104, and input module 106 have a substantially cylindrical outer profileand each lie substantially coaxial with a central axis 128 that extendsgenerally along the length of the cement head 100 and is generallylocated centrally within cross-sections of the cement head 100 that aretaken orthogonal to the central axis 128. Each intermediate module 104includes a launch valve 112 (discussed infra) while the output module102 includes a launch port 114 and a launch indicator 116 (eachdiscussed infra). The cement head 100 may further include safety modules130, 134 with embedded safety valves 132, 136, discussed in more detailbelow.

Referring now to FIG. 1B, a cross-sectional view of the cement head 100in a fully assembled state is shown. This view shows that the cementhead 100 includes primary fluid flow bores 166 extending through eachmodule 102, 104, 106 along the central axis 128. Also shown is that thecement head 100 includes bypass fluid flow bores 168 within eachintermediate module 104. The input module 106 includes a conical header170 into which fluid is passed and from which each of the primary fluidflow bores 166 and bypass fluid flow bores 168 are in fluidcommunication with, depending on the operational positions of the launchvalves 112. The bypass fluid flow path 168 generally begins at theinterface between the input module 106 and the adjacent intermediatemodule 104, so that fluid exiting the input module 106 and entering theadjacent intermediate module 104 is capable of passing through eitherthe primary fluid flow bore 166 or the bypass fluid flow bore 168,depending on the operational orientation of launch valves 112.

The cement head 100 may be used to perform a variety of functions thatare generally known in the art, some of which are described herein.Generally, flow through the cement head 100 would be from the left handside of FIG. 1B to the right hand side of FIG. 1B. When the cement head100 is installed in a work string, the input module 106 is locatedhigher than the output module 102 so that flow through the cement head100 would be generally from top to bottom from the input module 106 tothe output module 102. Flow through the cement head 100 enters eitherthrough the upper work string interface 110 or mixture ports 176, whichare fluidly coupled to the primary fluid flow bore 166 of the inputmodule 106, and exits through the lower work string interface 108.Additionally, the cement head 100 is capable of retaining and launchingdarts.

The launch valves 112 operate in two positions. The first position is abypass position where the launch valve prevents fluid flow directlythrough a primary fluid flow bore 166, but instead, allows fluid to flowfrom a bypass fluid flow bore 168 to a primary flow bore 166 on thedownstream side of the launch valve 112. The second position is aprimary position where the launch valve 112 allows fluid flow directlyfrom a position upstream from the launch valve 112 in a primary fluidflow bore 166 to a position downstream from the launch valve 112 in aprimary fluid flow bore 166.

The primary position is a position in which a dart, ball, or othermember to be launched is allowed to pass through the launch valve 112from the upstream side of the launch valve 112 to the downstream side ofthe launch valve 112. The launch valves 112 of FIG. 1B are positioned sothat a dart, ball, or other member to be launched is free to passthrough the downstream launch valve 112 (on the right side of thedrawing). To aid in pushing the dart or other object through thedownstream launch valve 112 (on the right side of the drawing), theupstream launch valve 112 is positioned in the bypass position so thatfluid can flow from the bypass fluid flow bore 168 into the primaryfluid flow bore 166 located upstream from the downstream launch valve112.

With the launch valves 112 in these positions, the upstream launch valve112 could be holding a second dart or other object to be launched. Withthe downstream launch valve 112 in the primary position, the upstreamlaunch valve 112 may be rotated one-quarter rotation from the bypassposition to the primary position, thereby allowing passage of the dartand fluids through the primary fluid flow bores 166. Launch port 114offers convenient access to a primary fluid flow bore 166 for allowingthe insertion of a ball to be dropped through the primary fluid flowbore 166. Launch indicator 116 uses lever arms to interfere with ballsand/or darts that pass by the launch indicator 116, resulting in arotation of an indicator portion of the launch indicator 116 to signifywhether a dart, ball, or other object has passed by the launch indicator116. In this embodiment, no part of the launch valves 112 extendradially beyond the full diameter sections 134, thereby reducing thechance of inadvertently breaking portions of the launch valves 112.

While not shown in this embodiment, alternative embodiments of a cementhead may integrate a safety valve (i.e., a ball valve having a full boreinside diameter, sometimes referred to as a TIW or Texas Iron Worksvalve) into one or more of the input module 106, intermediate modules104, and/or output module 102.

An embodiment of a cement head including safety valves is shown in FIG.1C. The cement head 100 may further include safety modules 130, 134.More particularly, a lower safety module 130 is connected to the outputmodule 102, while an upper safety module 134 is connected to the inputmodule 106 or the upper work string interface 110. The safety modules130, 134 are also connected to the work string or other tools andselectively allow a fluid connection between the safety modules 130,134. Specifically, each safety module 130, 134 includes a safety valve132, 136, respectively, that operates to selectively restrict fluid flowthrough the safety modules 130, 134.

Referring now to FIG. 1D, the cement head 100 may also include aninternal control line 162 that extends at least through adjacentintermediate modules 104. In this embodiment, the internal control line162 is well suited for communicating pneumatic control pressure/signalsto launch valves, such as the launch valves 112 of FIGS. 1A and 1B,thereby allowing remote control of the launch valves 112. While only oneinternal control line 162 is shown, it should be understood that inalternative embodiments, additional control lines may be used to controladditional launch valves, with at least one internal control line beingassociated with the control of each launch valve. By placing theinternal control line 162 inside the cement head 100 rather thanexternal to the modules, the chances for inadvertent damage to theinternal control line 162 is minimized. Also shown in FIG. 1D are theprimary fluid flow bore 166 and the bypass fluid flow bore 168.

FIG. 2 shows a front view of the cement head 100 in a fully assembledstate. FIG. 3 shows a side view of the cement head 100 in a fullyassembled state, including wrenches 190 provided for manual ormechanical actuation of each launch valve 112, the lower safety valve132, the upper safety valve 136, and the mixture valves 178. Manualoperation of such valves requires the presence of rig personnel toactuate or control one or more of these valves. An aspect of the presentdisclosure provides an ability to operate the valves of the cement head100 remotely.

Referring now to FIG. 4, an isometric view of the cement head 100 in afully assembled state is shown. Various onboard devices 200 (referred toas devices 200 a, 200 b, 200 c, 200 d, 200 e, and 200 f) are shown asbeing connected to the cement head 100. One or more of onboard devices200 a-f are operably connected to one or more mechanical devices of thecement head 100. Mechanical devices may include valves, levers,plungers, and the like. A first onboard device 200 a may be operablyconnected to the upper safety valve 136 of the upper safety module 134.A second onboard device 200 b may be operably connected to a mixtureport 176 of the input module 106. Additional onboard devices (not shown)may be provided to one or more of the other mixture ports 176 shown inFIG. 4. A third onboard device 200 c may be operably connected to thefirst launch valve 112 of the first intermediate module 104. Likewise, afourth onboard device 200 d may be operably connected to the secondlaunch valve 112 of the second intermediate module 104. A fifth onboarddevice 200 e may be operably connected to the launch port 114 of theoutput module 102. A sixth onboard device 200 f may be operablyconnected to the lower safety valve 132 of the lower safety module 130.

As shown in FIG. 4, the first, second, and sixth onboard devices 200 a,200 b, 200 f may each be housed in independent enclosures. As furthershown in FIG. 4, the third, fourth, and fifth onboard devices 200 c, 200d, and 200 e may be housed in a single enclosure. The enclosures may beattached to portions of the cement head 100. Alternatively, all or aportion of any of the onboard devices 200 a-f may be integrated withinthe main body of the cement head 100.

Referring now to FIG. 5, with continued reference to FIG. 4, a schematicview of a communication system 500 is shown. It will be appreciated thatitems depicted in FIG. 5 are not necessarily shown to scale. Thecommunication system 500 may include the cement head 100, a controldevice 300, and a tracking device 400. The control device 300 may beoperable by a user, such as a well operator or rig hand. One or moreinputs 314 are provided in the control device 300 for operation by theuser, with each of the inputs 314 having an associated function. Forexample, one of the inputs 314 may be associated with a specificoperation of a certain onboard device 200 a-f; e.g., open, partiallyopen, close, partially close, activate, deactivate, etc. Variousoperations and modes of the mechanical devices (e.g., valves) of thecement head 100 are disclosed herein.

The control device 300 further includes one or more displays 312 forproviding information to the user. The display 312 may be associatedwith the current state of the control device 300, one of the inputs 314,and/or the onboard devices 200 a-f. In operation, the control device 300may be configured to transmit first command signals 390 to one or moreof the onboard devices 200 a-f. According to some embodiments, thecontrol device 300 may be further configured to transmit second commandsignals 392 to the tracking device 400. The first and second commandsignals 390, 392 may be transmitted either wired or wirelessly. Inembodiments where the signals are 390, 392 are transmitted wirelessly,the control device 300 may include a wireless transmitter, as describedin more detail below.

The first and/or second command signals may encompass a user command(i.e., a user command indicator) provided by the user using one of theinputs 314. In some embodiments, the user command indicator may includea time that the control device 300 transmits the user command indicator.As used herein, an indicator including a time may have a timestampcorresponding to a time or span of time for an operation. The usercommand indicator may include instructions for an onboard device 200 tooperate an associated mechanical device.

According to some embodiments, the onboard devices 200 a-f may beconfigured to receive the first command signals 390 from the controldevice 300. In embodiments where the first command signals 390 arewireless signals, the onboard devices 200 a-f may each include awireless receiver or transceiver configured to receive and process thefirst command signals 390, as described in more detail below. Theonboard devices 200 a-f may be configured to operate their correspondingmechanical devices in response to the first command signals 390 from thecontrol device 300. In some embodiments, the onboard devices 200 a-f maybe further configured to operate one or more sensors in response to thesignals received from the control device 300.

According to some embodiments, the onboard devices 200 a-f may befurther configured to transmit report signals 290 to the tracking device400 either wired or wirelessly. In embodiments where the report signals290 signals are transmitted wirelessly, the onboard devices 200 a-f mayinclude wireless transmitters or transceivers, as described in moredetail below. The report signals 290 may contain an indication of astate (i.e., a status indicator) of the particular onboard device 200a-f, an associated mechanical devices, and/or the cement head 100. Insome embodiments, the status indicator may include a time that a commandindicator was received by an onboard device 200, a time that an onboarddevice 200 commences operation, and/or a time that an onboard device 200ceases operation. In some embodiments, the status indicator may includea parameter sensed by a sensor of the onboard device 200, and the statusindicator may include a time that the onboard device 200 transmits thereport signal 290.

According to some embodiments, the tracking device 400 may be configuredto receive the second command signals 392 from the control device 300.According to some embodiments, the tracking device 400 may further beconfigured to receive report signals 290 from the onboard devices 200.The tracking device 400 may be configured to record and store the secondcommand signals 392 and the report signals 290, along with anyassociated information or data.

Accordingly, the communication system 500 provides three communicationpathways interconnecting the control device 300, the onboard devices 200a-f, and the tracking device 400. As such, each component iscommunicatively linked to the others while potentially being disposed atseparate and remote locations. For instance, the onboard devices 200 a-fmay be located at a wellbore site for operation of the cement head 100in conjunction with other wellbore equipment. The control device 300 maybe operated remotely and at a distance away from the cement head 100 andthe onboard devices 200 a-f. Accordingly, the user of the control device300 may operate to control device 300 from a safe distance away from thecement head 100 and other wellbore equipment.

Similarly, the tracking device 400 may operate at a location that isremote relative to the onboard devices 200 a-f and the control device300.

The location of the tracking device 400 may include any equipment usefulfor the operation of the tracking device 400, such as components forstoring, uploading, or analyzing data collected by the tracking device400. Because the control device 300 and the tracking device 400 areseparate components, they may be located separately and remotely awayfrom each other while maintaining a communication link. Accordingly, auser operating the control device 300 may be able to position or movethe control device 300 to a variety of locations without correspondinglymoving the tracking device 400. Thus, the mobility and portability ofthe control device 300 is enhanced by separation thereof from thetracking device 400. As mentioned above, signals between the controldevice 300, the onboard devices 200 a-f, and the tracking device 400 maybe transmitted wirelessly to further enhance mobility.

According to some embodiments, the tracking device 400 includes one ormore interfaces 416 for communicating stored data to other devices. Datareceived, collected, and stored on the tracking device 400 may beaccessible to a user during or after a procedure involving the cementhead 100. Information collected from the control device 300 via commandsignals 392, and from the onboard devices 200 via the report signals290, may be correlated and compared in a meaningful way. For example, auser may analyze timing of commands and actuation of valves, levers,and/or plungers. The time span between the transmission of a usercommand from a control device 300 and the completion of an associatedoperation by the onboard device 200 a-f may be determined and analyzed.For instance, a user may be able to compare the period of time from whena wellbore projectile (i.e., dart, ball, plug, etc.) is released fromthe cement head 100 to a pressure spike once the wellbore projectilelands on a downhole tool, shoulder, or obstruction. Commands andoperations may also be compared with sensed parameters, such as pressureor temperature at or near one or more valves, levers, and/or plungers.The analysis may identify proper or improper operation, as well as anyneeded optimizations to improve performance of the cement head 100.

Referring now to FIG. 6, with continued reference to FIG. 5, aconceptual block diagram of the communication system 500 is shown. Thecontrol device 300 is configured to transmit the first command signals390, shown as command signals 390 a, 390 b, 390 c, 390 d, 390 e, and 390f. Each of the command signals 390 a-f may be associated with arespective onboard device 200 a-f. For example, the first command signal390 a carries a user command indicator relating to operation of thefirst onboard device 200 a. Data carried on a given command signal 390may contain a reference identifier indicating which of the onboarddevices 200 is intended to respond to the given command signal 390. Datacarried on a given command signal 390 may contain an instruction thatthe intended onboard device 200 is to execute.

The control device 300 is also configured to transmit the second commandsignals 392, shown as command signals 392 a, 392 b, 392 c, 392 d, 392 e,and 392 f. Each of the command signals 392 a-f may be associated with arespective onboard device 200 a-f. Moreover, each of the command signals392 a-f may be transmitted for reception by the tracking device 400. Insome embodiments, a given pair of command signals 390 and 392 may carrythe same user command indicator. For example, the given pair of commandsignals 390 and 392 are transmitted at or about the same time. In someembodiments, a pair of command signals 390 and 392 may be separatepropagations of a single signal. For example, the pair of commandsignals 390 and 392 may be different directional components of amulti-directional broadcast.

The onboard devices 200 a-f may be configured to transmit the reportsignals 290 a-f, respectively. Each of the report signals 290 a-f maycarry information associated with the corresponding onboard device 200a-f. Moreover, each of the report signals 290 a-f may be received by thetracking device 400. A given report signal (e.g., report signal 290 a)may be correlated with a corresponding command signal (e.g., commandsignal 392 a).

Referring now to FIG. 7, with continued reference to FIGS. 5 and 6, aconceptual block diagram of the communication system 500 is shown. Thecontrol device 300 may include a processing system 302. The processingsystem 302 is capable of communication with a transmitter 309 through abus 304 or other structures or devices. The processing system 302 cangenerate commands and/or other types of data to be provided to thetransmitter 309 for communication by command signals 390, 392. In someembodiments, the control device 300 may also include a receiver (notshown) and a power source (not shown).

The processing system 302 may include a processor for executinginstructions and may further include a non-transitory machine-readablemedium 319, such as a volatile or non-volatile memory, for storing dataand/or instructions for software programs. The instructions may beexecuted by the processing system 302 to control and manage access tothe various networks, as well as provide other communication andprocessing functions. The instructions may also include instructionsexecuted by the processing system 302 for various components of thecontrol device 300, such as a display 312, an input 314, and aninterface 316.

The onboard device 200 shown in FIG. 7 is representative of any one ofthe onboard devices 200 a-f of FIGS. 4-6. The onboard device 200 mayinclude a processing system 202 capable of communication with a receiver206 and a transmitter 209 through a bus 204 or other structures ordevices. The processing system 202 can acquire, record, and generatedata to be provided to the transmitter 209 for communication as thereport signal 290. In addition, commands and/or other types of data,communicated as the command signal 390, can be received at the receiver206 and processed by the processing system 202. A transceiver block 207may represent one or more transceivers, and each transceiver may includea receiver 206 and a transmitter 209. 207

The processing system 202 may include a processor for executinginstructions and may further include a non-transitory machine-readablemedium 219, such as a volatile or non-volatile memory, for storing dataand/or instructions for software programs. The instructions, which maybe stored in the machine-readable medium 219, may be executed by theprocessing system 202 to control and manage access to the variousnetworks, as well as provide other communication and processingfunctions. The instructions may also include instructions executed bythe processing system 202 for various components of the onboard device200, such as an onboard control 214 and one or more sensors 216.

According to some embodiments, the onboard device 200 may be configuredto operate a corresponding mechanical device to which it is operablyconnected. For example, each onboard device 200 includes an onboardcontrol 214 configured to open, partially open, close, partially close,activate, and/or deactivate a corresponding valve. Such actions may beachieved by rotating or moving the valve. For example, the onboarddevice 200 may include a pneumatic actuator that operates a cell,canister, or tank of a compressible fluid for operation of a valve. Thecompressible fluid may include nitrogen, oxygen, air, or anycompressible gas. At least a portion of the pneumatic actuator mayconnect to a chamber of the cement head 100, such as the internalcontrol line 162 shown in FIG. 1D. In other embodiments, the onboarddevice 200 may include any other type of actuating device capable ofmanipulating a corresponding valve including, but not limited to,mechanical actuators, electromechanical actuators, hydraulic actuators,piston and solenoid assemblies, combinations thereof, and the like. Byfurther example, such actions may be applied to other mechanical devicesof the cement head 100, such as levers and/or plungers.

According to some embodiments, the onboard device 200 may further beconfigured to sense, detect, and/or measure one or more parameters of acorresponding mechanical device to which it is operably connected or oneor more parameters of the cement head 100. For example, the sensors 216may be sensitive to a state of the mechanical device (e.g., open,partially open, closed, partially closed, present, absent, and thelike). For example, the sensors 216 may detect a time at which amechanical device changes from one state (e.g., open) to another state(e.g., closed). The sensors 216 may detect the presence, absence, ormotion of a plunger and an associated time. For example, one or moresensors 216 may detect a time at which a plunger is released and a timethat the plunger arrives at a given location after release. The sensors216 may further be sensitive to conditions within the cement head 100(e.g., pressure, flow rate, temperature, proximity sensors, and thelike). As will be appreciated, multiple sensors may be provided in orotherwise associated with each onboard device 200, each having adistinct sensitivity and function. In at least one embodiment, one ormore sensors may also be installed in wellbore projectiles to belaunched from the cement head 100.

According to some embodiments, the onboard device 200 may include apower source 212 for operation. For example, the power source 212 powersoperation of the onboard control 214, the sensors 216, the receiver 206,the transmitter 209, and/or the processing system 202. The power source212 may include a battery (e.g., a rechargeable battery), a generator, asolar panel, and/or combinations thereof. As will be appreciated, asingle power source 212 may be configured to provide power to more thanone onboard device 200.

The tracking device 400 may include a processing system 402. Theprocessing system 402 is capable of communication with a receiver 406through a bus 404 or other structures or devices. Reports and/or othertypes of data, communicated as the report signal 290, can be received atthe receiver 406 and processed by the processing system 402. Thetracking device 400 may also include a transmitter (not shown). Thetracking device 400 may also include a power source (not shown).

The processing system 402 may include a processor for executinginstructions and may further include a non-transitory machine-readablemedium 419, such as a volatile or non-volatile memory, for storing dataand/or instructions for software programs. The instructions, which maybe stored in a non-transitory machine-readable medium 410 and/or 419,may be executed by the processing system 402 to control and manageaccess to the various networks, as well as provide other communicationand processing functions. The instructions may also include instructionsexecuted by the processing system 402 for various components of thetracking device 400, such as an interface 416 and the machine-readablemedium 419. The machine-readable medium 419 provides storage of dataapart from the processing system 402. For example, data communicated asthe report signal 290 may be recorded or otherwise stored in themachine-readable medium 419. The data may be further communicatedbetween the tracking device 400 and another device, such as a computer,a server, or a hand-held device, for display, review, analysis, ormanipulation.

The processing systems 202, 302, 402 may be implemented using software,hardware, or a combination of both. By way of example, the processingsystems 202, 302, 402 may each be implemented with one or moreprocessors. A processor may be a general-purpose microprocessor, amicrocontroller, a Digital Signal Processor (DSP), an ApplicationSpecific Integrated Circuit (ASIC), a Field Programmable Gate Array(FPGA), a Programmable Logic Device (PLD), a controller, a statemachine, gated logic, discrete hardware components, or any othersuitable device that can perform calculations or other manipulations ofinformation.

A machine-readable medium can be one or more machine-readable media.Software shall be construed broadly to mean instructions, data, or anycombination thereof, whether referred to as software, firmware,middleware, microcode, hardware description language, or otherwise.Instructions may include code (e.g., in source code format, binary codeformat, executable code format, or any other suitable format of code).

Machine-readable media (e.g., 219, 319, 419) may include storageintegrated into a processing system, such as might be the case with anASIC. Machine-readable media (e.g., 410) may also include storageexternal to a processing system, such as a Random Access Memory (RAM), aflash memory, a Read Only Memory (ROM), a Programmable Read-Only Memory(PROM), an Erasable PROM (EPROM), registers, a hard disk, a removabledisk, a CD-ROM, a DVD, or any other suitable storage device. Thoseskilled in the art will recognize how best to implement the describedfunctionality for the processing systems 202, 302, 402. According to oneaspect of the disclosure, a machine-readable medium is acomputer-readable medium encoded or stored with instructions and is acomputing element, which defines structural and functionalinterrelationships between the instructions and the rest of the system,which permit the instructions' functionality to be realized. In oneaspect, a machine-readable medium is a non-transitory machine-readablemedium, a machine-readable storage medium, or a non-transitorymachine-readable storage medium. In one aspect, a computer-readablemedium is a non-transitory computer-readable medium, a computer-readablestorage medium, or a non-transitory computer-readable storage medium.Instructions may be executable, for example, by a client device orserver or by a processing system of a client device or server.Instructions can be, for example, a computer program including code.

The interfaces 316, 416 may be any type of interface and may residebetween any of the components shown in FIG. 7. The interfaces 316, 416may also be, for example, an interface to the outside world (e.g., anInternet network interface). A functionality implemented in a processingsystem may be implemented in a portion of a receiver, a portion of atransmitter, a portion of a machine-readable medium, a portion of adisplay, a portion of a keypad, or a portion of an interface, and viceversa.

As mentioned above, components (i.e., transmitters, receivers) of theonboard device 200, the control device 300, and the tracking device 400may be configured to perform wired or wireless communication. Thetransmitters and receivers may send and receive radio frequency (RF)signals, infrared (IR) frequency signals, or other electromagneticsignals. Any of a variety of modulation techniques may be used tomodulate data on a respective electromagnetic carrier wave.Alternatively, wired communications may also be performed.Communications protocols for managing communication are known, and mayinclude IEEE 802.11, IEEE 802.3, USB-compatible, Bluetooth, etc.

Referring now to FIG. 8, a flow chart illustrating a method 800 isshown. Various steps performed by the control device 300, the onboarddevice 200, and the tracking device 400 are illustrated.

As shown in FIG. 8, a user may provide a user command to the controldevice 300, as at 802. In response, the control device 300 transmits auser command indicator via a first command signal 390 and a secondcommand signal 392, as at 804. In response to the first command signal390, the onboard device 200 may operate a mechanical device, such as avalve, a lever, or a plunger, as at 806, and/or sense a parameter, as at808. Furthermore, the onboard device 200, in response to the firstcommand signal 390 or an additional command signal, may cease operationof the mechanical device, as at 810, and/or sense an additionalparameter, as at 812. Each operation performed or parameter sensed bythe onboard device 200 may generate a status indicator transmitted via areport signal 290, as at 814. Multiple report signals 290 may betransmitted or a single report signal 290 containing multiple datavalues may be transmitted.

As further shown in FIG. 8, the tracking device 400 receives the secondcommand signal 392 and its associated user command indicator. Inresponse, the tracking device 400 records the user command indicator, asat 816. Further, the tracking device 400 receives the report signal 290and its associated status indicator from the onboard device 200. Inresponse, the tracking device 400 records the status indicator, as at818.

Additional user commands may be provided to the control device 300 atany time during the operation described and illustrated in FIG. 8. Theadditional user commands may the control device 300, the onboard device200, and/or the tracking device 400 to perform additional operationssubsequent to or simultaneous with previously initiated operations.

The steps illustrated, a subset of the steps illustrated, or additionalsteps may be performed in any order. Any two or more steps may beperformed in series or in parallel (e.g., simultaneously). Furthermore,operations associated with the control device 300, the onboard device200, or the tracking device 400 as illustrated in FIG. 8 may beperformed by a device other than the device as shown in FIG. 8. Multiplemethods 800 may be performed in series or in parallel. For example, amethod 800, or portions thereof, may be performed for each of aplurality of onboard devices 200.

Embodiments disclosed herein include:

A. A system that includes a control device configured to transmit usercommand indicators in the form of first command signals and secondcommand signals, an onboard device operably connected to a mechanicaldevice of a cement head and configured to receive the first commandsignals from the control device and operate the mechanical device inresponse thereto, the onboard device being further configured to prepareand transmit a report signal, wherein the report signal encompasses astatus indicator of the cement head, and a tracking device configured toreceive the second command signals from the control device and thestatus indicator from the onboard device, the tracking device beingfurther configured to record the user command indicators and the statusindicator.

B. A method that includes transmitting a first command signal to anonboard device from a control device, operating a mechanical device of acement head with the onboard device in response to the first commandsignal, transmitting a report signal to a tracking device, the reportsignal encompassing a status indicator of the cement head, recording thestatus indicator from the onboard device with the tracking device,transmitting the user command indicator from the control device to thetracking device via a second command signal, and recording the usercommand indicator with the tracking device.

C. A method that includes transmitting a first command signal to anonboard device with a control device, transmitting a second commandsignal to a tracking device with the control device, operating amechanical device of a cement head with the onboard device in responseto the first command signal, transmitting a status indicator of thecement head from the onboard device to the tracking device via a reportsignal, and recording the status indicator and the second command signalwith the tracking device.

Each of embodiments A, B, and C may have one or more of the followingadditional elements in any combination: Element 1: wherein the usercommand indicator comprises a time that the control device transmits theuser command indicator. Element 2: wherein the status indicatorcomprises a time that the onboard device receives the first commandsignals, a parameter sensed by a sensor of the onboard device, a timethat the onboard device commences an operation of the mechanical device,or a time that the onboard device ceases an operation of the mechanicaldevice. Element 3: further comprising a report signal wherein the firstcommand signal, the second command signal, and the report signal arewireless signals. Element 4: wherein the control device comprises awireless transmitter, the onboard device comprises a wireless receiverand a wireless transmitter, and the tracking device comprises a wirelessreceiver. Element 5: wherein the onboard device comprises a sensorconfigured to sense one or more parameters of the cement head. Element6: wherein the mechanical device is a valve, a lever, or a plunger.

Therefore, the disclosed systems and methods are well adapted to attainthe ends and advantages mentioned as well as those that are inherenttherein. The particular embodiments disclosed above are illustrativeonly, as the teachings of the present disclosure may be modified andpracticed in different but equivalent manners apparent to those skilledin the art having the benefit of the teachings herein. Furthermore, nolimitations are intended to the details of construction or design hereinshown, other than as described in the claims below. It is thereforeevident that the particular illustrative embodiments disclosed above maybe altered, combined, or modified and all such variations are consideredwithin the scope of the present disclosure. The systems and methodsillustratively disclosed herein may suitably be practiced in the absenceof any element that is not specifically disclosed herein and/or anyoptional element disclosed herein. While compositions and methods aredescribed in terms of “comprising,” “containing,” or “including” variouscomponents or steps, the compositions and methods can also “consistessentially of” or “consist of” the various components and steps. Allnumbers and ranges disclosed above may vary by some amount. Whenever anumerical range with a lower limit and an upper limit is disclosed, anynumber and any included range falling within the range is specificallydisclosed. In particular, every range of values (of the form, “fromabout a to about b,” or, equivalently, “from approximately a to b,” or,equivalently, “from approximately a-b”) disclosed herein is to beunderstood to set forth every number and range encompassed within thebroader range of values. Also, the terms in the claims have their plain,ordinary meaning unless otherwise explicitly and clearly defined by thepatentee. Moreover, the indefinite articles “a” or “an,” as used in theclaims, are defined herein to mean one or more than one of the elementthat it introduces. If there is any conflict in the usages of a word orterm in this specification and one or more patent or other documentsthat may be incorporated herein by reference, the definitions that areconsistent with this specification should be adopted.

1. A system, comprising: a control device configured to transmit usercommand indicators in the form of first command signals and secondcommand signals; an onboard device operably connected to a mechanicaldevice of a cement head and configured to receive the first commandsignals from the control device and operate the mechanical device inresponse thereto, the onboard device being further configured to prepareand transmit a report signal, wherein the report signal encompasses astatus indicator of the cement head; and a tracking device configured toreceive the second command signals from the control device and thestatus indicator from the onboard device, the tracking device beingfurther configured to record the user command indicators and the statusindicator.
 2. The system of claim 1, wherein the user command indicatorcomprises a time that the control device transmits the user commandindicator.
 3. The system of claim 1, wherein the status indicatorcomprises a time that the onboard device receives the first commandsignals, a parameter sensed by a sensor of the onboard device, a timethat the onboard device commences an operation of the mechanical device,or a time that the onboard device ceases an operation of the mechanicaldevice.
 4. The system of claim 1, further comprising a report signalwherein the first command signal, the second command signal, and thereport signal are wireless signals.
 5. The system of claim 1, whereinthe control device comprises a wireless transmitter, the onboard devicecomprises a wireless receiver and a wireless transmitter, and thetracking device comprises a wireless receiver.
 6. The system of claim 1,wherein the onboard device comprises a sensor configured to sense one ormore parameters of the cement head.
 7. The system of claim 1, whereinthe mechanical device is a valve, a lever, or a plunger.
 8. A method,comprising transmitting a first command signal to an onboard device froma control device; operating a mechanical device of a cement head withthe onboard device in response to the first command signal; transmittinga report signal to a tracking device, the report signal encompassing astatus indicator of the cement head; recording the status indicator fromthe onboard device with the tracking device; transmitting the usercommand indicator from the control device to the tracking device via asecond command signal; and recording the user command indicator with thetracking device.
 9. The method of claim 8, wherein the user commandindicator comprises a time that the control device transmits the usercommand indicator.
 10. The method of claim 8, wherein the statusindicator comprises a time that the onboard device receives the usercommand indicator.
 11. The method of claim 8, wherein the statusindicator comprises a parameter sensed by a sensor of the onboarddevice.
 12. The method of claim 8, wherein the status indicatorcomprises a time that the onboard device commences an operation of themechanical device.
 13. The method of claim 8, wherein the statusindicator comprises a time that the onboard device ceases an operationof the mechanical device.
 14. The method of claim 8, further comprisingwirelessly transmitting and receiving the first command signal, thesecond command signal, and the report signal.
 15. The method of claim 8,wherein the first command signal comprises a time that the controldevice transmits the first command signal.
 16. The system method ofclaim 8, wherein the mechanical device is a valve, a lever, or aplunger.
 17. A method, comprising: transmitting a first command signalto an onboard device with a control device; transmitting a secondcommand signal to a tracking device with the control device; operating amechanical device of a cement head with the onboard device in responseto the first command signal; transmitting a status indicator of thecement head from the onboard device to the tracking device via a reportsignal; and recording the status indicator and the second command signalwith the tracking device.
 18. The method of claim 17, wherein one orboth of the first and second command signals comprises a time that thecontrol device transmits the first or second command signals.
 19. Themethod of claim 17, wherein the status indicator comprises a time thatthe onboard device receives the first command signal.
 20. The method ofclaim 17, wherein the status indicator comprises a parameter sensed by asensor of the onboard device.
 21. The method of claim 17, wherein thestatus indicator comprises a time that the onboard device commences anoperation of the mechanical device.
 22. The method of claim 17, whereinthe status indicator comprises a time that the onboard device ceases anoperation of the mechanical device.
 23. The method of claim 17, furthercomprising wirelessly transmitting and receiving the first commandsignal, the second command signal, and the report signal.
 24. The systemmethod of claim 17, wherein the mechanical device is a valve, a lever,or a plunger.